Methods and Devices for Forming a Wellbore with Casing

ABSTRACT

A method for cementing a tubular in a wellbore in a subterranean formation, according to one or more aspects of the present disclosure, comprises connecting a circulating tool to a slip and a top drive; gripping a first tubular with the slip above the surface of the wellbore; sealingly engaging the first tubular with a seal member; fluidly connecting a wiper plug to the circulating tool; connecting the first tubular to a second tubular; and lowering the second tubular into the subterranean formation.

RELATED APPLICATIONS

This application is a continuation of U.S. patent application Ser. No.12/114,755, filed on May 3, 2008, (now U.S. Pat. No. 7,635,016), whichis a continuation of U.S. patent application Ser. No. 11/512,601, filedon Aug. 29, 2006, now U.S. Pat. No. 7,379,698, which is a continuationof U.S. patent application Ser. No. 10/047,727, filed on Jan. 15, 2002,now U.S. Pat. No. 7,096,948, which is a continuation of U.S. patentapplication Ser. No. 09/837,447, filed on Apr. 17, 2001, now abandoned,which is a continuation of U.S. patent application Ser. No. 09/206,876,filed on Dec. 8, 1998, now U.S. Pat. No. 6,279,654, which is acontinuation-in-part of U.S. patent application Ser. No. 08/850,496,filed on May 2, 1997, now U.S. Pat. No. 5,918,673, which is acontinuation-in-part of U.S. patent application Ser. No. 08/726,112,filed on Oct. 4, 1996, now U.S. Pat. No. 5,735,348.

This Application is related to U.S. patent application Ser. No.10/052,855, filed on Jan. 15, 2002, now U.S. Pat. No. 6,595,288; andU.S. patent application Ser. No. 11/555,391, filed on Nov. 1, 2006.

FIELD OF THE INVENTION

This invention relates generally to equipment used in the drilling andcompletion of subterranean wells, and more specifically to the fillingand circulating of drilling fluids in a casing string as well as pumpingcement into the casing to set the casing within the wellbore.

BACKGROUND

The process of drilling subterranean wells to recover oil and gas fromreservoirs consists of boring a hole in the earth down to the petroleumaccumulation and installing pipe from the reservoir to the surface.Casing is a protective pipe liner within the wellbore that is cementedin place to insure a pressure-tight connection to the oil and gasreservoir. The casing is run a single joint at a time as it is loweredinto the wellbore. On occasion, the casing becomes stuck and is unableto be lowered into the wellbore. When this occurs, load or weight mustbe added to the casing string to force the casing into the wellbore, ordrilling fluid must be circulated down the inside diameter of the casingand out of the casing into the annulus in order to free the casing fromthe wellbore. To accomplish this, it has traditionally been the casethat special rigging be installed to add axial load to the casing stringor to facilitate circulating the drilling fluid.

When running casing, drilling fluid is added to each section as it isrun into the well. This procedure is necessary to prevent the casingfrom collapsing due to high pressures within the wellbore. The drillingfluid acts as a lubricant which facilitates lowering the casing withinthe wellbore. As each joint of casing is added to the string, drillingfluid is displaced from the wellbore. The prior art discloses hoseassemblies, housings coupled to the uppermost portion of the casing, andtools suspended from the drill hook for filling the casing. These priorart devices and assemblies have been labor intensive to install,required multiple such devices for multiple casing string sizes, havenot adequately minimized loss of drilling fluid, and have not beenmulti-purpose. Further, disengagement of the prior art devices from theinside of the casing has been problematic, resulting in damage to thetool, increased downtime, loss of drilling fluid, and injury topersonnel.

The normal sequence for running casing involves suspending the casingfrom a top drive or non-top drive (conventional rotary rig) and loweringthe casing into the wellbore, filling each joint of casing with drillingfluid. The filling of each joint or stand of casing as it is run intothe hole is the fill-up process. Lowering the casing into the wellboreis facilitated by alternately engaging and disengaging elevator slipsand spider slips with the casing string in a stepwise fashion,facilitating the connection of an additional stand of casing to the topof the casing string as it is run into the hole.

Circulation of the fluid is sometimes necessary if resistance isencountered as the casing is lowered into the wellbore, preventing therunning of the casing string into the hole. This resistance to runningthe casing into the hole may be due to such factors as drill cuttings,mud cake, or surface tension formed or trapped within the annulusbetween the well bore and the outside diameter of the casing, or cavingof the wellbore among other factors. In order to circulate the drillingfluid, the top of the casing must be sealed so that the casing may bepressurized with drilling fluid. Since the casing is under pressure theintegrity of the seal is critical to safe operation, and to minimize theloss of expensive drilling fluid. Once the obstruction is removed thecasing may be run into the hole as before.

Once the casing reaches the bottom, circulating of the drilling fluid isagain necessary to test the surface piping system, to condition thedrilling fluid in the hole, and to flush out wall cake and cuttings fromthe hole. Circulating is continued until at least an amount of drillingfluid equal to the volume of the inside diameter of the casing has beendisplaced from the casing and wellbore. After the drilling fluid hasbeen adequately circulated, the casing may be cemented in place.

On jobs which utilize a side door elevator, the casing is simplysuspended from a shoulder on the elevator by the casing collar. Thus,fill-up and circulation tools with friction fit sealing elements such aspacker cups, and other elastomeric friction fit devices must repeatedlybe inserted and removed because of the overall length requirements ofthe tool. This repeated insertion will, over time, result in the wearingof the elastomeric sealing element such that it will no longerautomatically seal on insertion. An adjustable extension is disclosed,which allows the fill-up and circulation tool to be retracted to preventthe elastomeric seal from being inserted into the casing during thefill-up process.

Circulation alone may be insufficient at times to free a casing stringfrom an obstruction. The prior art discloses that the fill-up andcirculation tools must be rigged down in order to install toolassemblies to attach to the rig to allow the string to be rotated andreciprocated. This process requires manual labor, inherent in which isthe possibility of injury or loss of life, and results in rig downtime.The potential for injury and lost rig time is a significant monetaryconcern in drilling operations. To eliminate his hazard and minimizelost rig time, a method and apparatus is disclosed, which allows thefill-up and circulation tool to remain rigged up while at the same timeallowing the casing to be rotated and reciprocated.

After the casing has been run to the desired depth it may be cementedwithin the wellbore. The purpose of cementing the casing is to seal thecasing to the wellbore formation. In order to cement the casing withinthe wellbore, the assembly to fill and circulate drilling fluid isgenerally removed from the drilling rig and a cementing head apparatusinstalled. This process is time consuming, requires significantmanpower, and subjects the rig crew to potential injury when handlingand installing the additional equipment flush the mud out with waterprior to the cementing step. A special cementing head or plug containeris installed on the top portion of the casing being held in place by theelevator. The cementing head includes connections for the discharge lineof the cement pumps, and typically includes a bottom wiper plug and atop wiper plug. Since the casing and wellbore are full of drillingfluid, it is first necessary to inject a spacer fluid to segregated thedrilling fluid from the cement to follow. The cementing plugs are usedto wipe the inside diameter of the casing and serves to separate thedrilling fluid from the cement, as the cement is carried down the casingstring. Once the calculated volume of cement required to fill theannulus has been pumped, the top plug is released from the cementinghead. Drilling fluid or some other suitable fluid is then pumped inbehind the top plug, thus transporting both plugs and the cementcontained between the plugs to an apparatus at the bottom of the casingknown as a float collar. Once the bottom plug seals the bottom of thecasing, the pump pressure increases, which ruptures a diaphragm in thebottom of the plug. This allows the calculated amount of cement to flowfrom the inside diameter of the casing to a certain level within theannulus being cemented. The annulus is the space within the wellborebetween the ID of the wellbore and the OD of the casing string. When thetop plug comes in contact with the bottom plug, pump pressure increasesindicating that the cementing process has been completed. Once thepressure is lowered inside the casing, a special float collar checkvalve closes, which keeps cement from flowing from the outside diameterof the casing back into the inside diameter of the casing.

The prior art discloses separate devices and assemblies for (1) fillingand circulating drilling fluid, and (2) cementing operations. The priorart devices for filling and circulating drilling fluid disclose a packertube, which requires a separate activation step once the tool ispositioned within the casing. The packer tubes are known in the art tobe subject to malfunction due to plugging, leaks, and the like, whichlead to downtime. Since each step in the well drilling process ispotentially dangerous, time consuming, labor intensive and thereforeexpensive, there remains a need in the art to minimize any down time.There also remains a need in the art to minimize tool change out and theinstallation of component pieces.

Therefore, there remains a need in the drilling of subterranean wellsfor a tool which can be used for drilling fluid, filling andcirculating, and for cementing operations.

For the foregoing reasons, there is a need for a drilling fluid filling,circulating, and cementing tool which can be installed quickly duringdrilling operations.

For the foregoing reasons, there is a need for a drilling fluid filling,circulating, and cementing tool which seals against the inside diameterof a casing having a self-energizing feature.

For the foregoing reasons, there is a need for a drilling fluid filling,circulating, and cementing tool which minimizes the waste of drillingfluids and allows for the controlled depressurization of the system.

For the foregoing reasons, there is a need for a drilling fluid filling,circulating, and cementing tool which may be used for every casing size.

For the foregoing reasons, there is a need for a drilling fluid filling,circulating, and cementing tool which submits additional axial loads tobe added to the casing string when necessary.

For the foregoing reasons, there is a need for a drilling fluid filling,circulating, and cementing tool which is readily adjustable in lengthsuch that damage to the sealing element is minimized.

For the foregoing reasons, there is a need for a fill-up and circulatingtool which may be sealingly coupled to a casing string to allow thestring to be rotated and reciprocated into the wellbore.

SUMMARY

In view of the foregoing and other considerations, the present inventionrelates to wellbore drilling and completion operations. Accordingly,examples of devices, systems, and methods for forming wellbores areprovided.

An apparatus for cementing tubulars in a wellbore, according to one ormore aspects of the present disclosure, comprises a top drive having afluid path; a gripping member supported above the wellbore comprisingradially movable gripping elements; and a wiper plug assembly fluidlyconnected to the fluid path.

An apparatus for cementing casing in a wellbore, according to one ormore aspects of the present disclosure, comprises a tubular body havinga fluid flow path therethrough; a seal member connectable to the tubularbody and the casing; a wiper plug connectable to the tubular body; agripping member supported above the wellbore to grip the casing; and atop drive to move the tubular body.

A method for cementing a tubular in a wellbore in a subterraneanformation, according to one or more aspects of the present disclosure,comprises connecting a circulating tool to a slip and a top drive;gripping a first tubular with the slip above the surface of thewellbore; sealingly engaging the first tubular with a seal member;fluidly connecting a wiper plug to the circulating tool; connecting thefirst tubular to a second tubular; and lowering the second tubular intothe subterranean formation.

A method of cementing a casing within a wellbore formed in a formation,according to one or more aspects of the present disclosure, comprisesconnecting a gripping member disposed above the wellbore, a cementingassembly and a top drive, wherein the top drive and the cementingassembly are fluidly connected to a fluid path; gripping the casing withthe gripping member and the top drive; sealingly engaging the casingwith a seal member; moving the casing within the wellbore via the topdrive; and cementing the casing within the formation while maintaining asealing engagement of the casing.

A method for cementing casing in a wellbore, according to one or moreaspects of the present disclosure, comprises disposing a tubular bodyhaving a seal member from a top drive, wherein a fluid path is formedthrough the top drive and tubular body; detachably connecting a wiperplug to the tubular body; gripping the casing with a slip above thesurface of the wellbore; fluidly sealing the casing above the surface ofthe wellbore with the seal member; moving the casing in the wellbore viathe top drive; releasing the wiper plug from the tubular body into thecasing; and cementing the casing within the wellbore.

A method for cementing casing in a wellbore, according to one or moreaspects of the present disclosure, comprises disposing a tubular bodyhaving a seal member from a drilling rig; detachably connecting a wiperplug to the tubular body; gripping the casing above the surface of thewellbore with a slip; sealingly engaging the casing above the surface ofthe wellbore with the seal member; moving the casing in the wellbore;releasing the wiper plug from the tubular body into the casing; andcementing the casing within the wellbore.

The foregoing has outlined some of the features and technical advantagesof the present invention in order that the detailed description of theinvention that follows may be better understood. Additional features andadvantages of the invention will be described hereinafter which form thesubject of the claims of the invention.

BRIEF DESCRIPTION OF THE DRAWINGS

FIG. 1 shows a top drive rig assembly in accordance with the presentinvention.

FIG. 2 shows a conventional rotary rig assembly used in accordance withthe present invention.

FIG. 3 shows a side view of the torque sub and the adjustable extension.

FIG. 3A shows a side view of the fill up and circulating tool in thefill-up mode and configured for a top drive rig assembly.

FIG. 4 shows a side view of the fill up and circulating tool in thefill-up mode and configured for a conventional rotary rig assembly.

FIG. 5 shows a side view of the fill up and circulating tool in thecementing mode and configured for a top drive rig assembly.

FIG. 6 shows a side view of the fill up and circulating tool configuredwith the push plate assembly.

FIG. 7 is a partial, cross-sectional view of another embodiment of afill up and circulating tool having a pressure relief housing.

FIG. 8 is a partial, cross-sectional view of the pressure relief housingof FIG. 7.

FIG. 9 is a partial, cross-sectional view of the pressure relief housingof FIG. 7.

DETAILED DESCRIPTION

FIG. 1 shows a top drive drilling rig 3. FIG. 1 also shows the casingfill up and circulator tool 46 in the top drive configuration, which ismore fully described below. Those skilled in the art will know thatsuspended from the traveling block 1 on a drilling rig is a hook 2. Thetop drive unit 3 is suspended from the hook 2. Pressurized fluid isdelivered from the drilling fluid pumps 8 through hose 4 directly to thetop drive unit 3. A top sub box connection assembly 6 is threadedlyconnected at one end to the top drive pin shoulder 5 to receive the fillup and circulating tool 46. The opposite end of the top sub boxconnection assembly is threadedly connected to the casing fill up andcirculating tool 46. A tool catch plate 7 may be fixed to the top subbox connection assembly 6 as a stop which will engage against theuppermost portion of the casing if the tool becomes disengaged from thetop drive unit 3. An elevator 14 is suspended from bails 3 a and 3 battached to the top drive unit 3. It should be obvious to one skilled inthe art that a joint of casing 32 may be positioned under the top driveunit so as to allow the upper end of the casing to be gripped by theelevator 14, thereby inserting the fill up and circulating tool 46partially inside of the casing 32. The casing 32, suspended from theelevator 14 may then be lowered through the rotary table slips 10 on thedrilling rig floor and rotary table 11 below the rig floor and into thewellbore 12. As the casing 32 is being lowered it may be filled withdrilling fluid from the fill up and circulating tool 46, the fulloperation of which is more fully described below. Once the casing 32 islowered such that the elevator 14 is almost in contact with the rotarytable slips 10, the slips 10 are then engaged against the casing 32 tohold it in position above the rig floor to receive the next joint ofcasing 32. The procedure is repeated until the entire casing string hasbeen lowered into the wellbore 12.

FIG. 2 is illustrative of a conventional drilling rig with a rotary typerig assembly with the casing circulating tool installed 46. Thoseskilled in the art will know that suspended from the traveling block ona rotary type rig configuration is a hook 2. The hook 2 includes twoears 2 a and 2 b, located on either side of the hook 2, and are used tosuspend a pair of bails 13 a and 13 b and an elevator 14 below. Thelower end of the bails 13 a and 13 b are connected to the ears 14 a and14 b of the elevator 14. The hook 2, also suspends a guide plate 15connected by a U-bolt 16, which is secured to the guide plate 15 withnuts 16 a and 16 b. The U-bolt 16 extends through apertures 15 c and 15d in the guide plate 15. The bails 13 a and 13 b extend through twoapertures 15 a and 15 b in the guide plate 15 such that horizontalmovement of the bails 13 a and 13 b, the elevator 14, and the fill upand circulating tool 46 is limited. The lock block 18 having a centralaxial bore is welded at one end to the bottom surface 15 e of the guideplate 15. The lock block 18 includes at least one aperture 18 aextending through the wall of the lock block 18 to receive spring pin 18b. Spring pin 18 b is adapted to releasably extend through the lockblock aperture 18 a and to engage the channel 17 a in the upper end ofthe bayonet adapter 17 on the fill-up and circulating tool 46. Thespring pin 18 b is inserted through the aperture 18 and into the channel17 a to retain the bayonet adapter 18 within the lock block 18 therebysuspending the fill-up and circulating tool 46 from the guide plate 15.To deliver fluid to the casing, the drilling fluid pump 8 is activatedwhich discharges drilling fluid into hose 4, and into the fill-up andcirculating tool through the nozzle 17 b on the bayonet adapter 17,which transports the drilling fluid to the fill-up and circulating tool46 and into the casing 32. Alternative embodiments of the lock block andbayonet adapter are contemplated by the present invention. For example,lock block 18 comprises a cylinder with internal threads and the bayonetadapter with a male threaded end so as to be threadedly connected to thelock block. In a second alternative embodiment, lock block 18 comprisesa cylinder with two apertures extending through the wall of the cylinder180 apart with the cylinder having an outside diameter slightly smallerthan the inside diameter of the lock block. The upper end of the bayonetadapter is inserted inside the lock block with the apertures inalignment. A pin would then be inserted through the apertures to retainthe bayonet adapter and therefore the fill-up and circulation tool.

FIG. 3 is illustrative of a torque sub 70 and a rotational sub 80, bothor either of which may be used in combination with any fill-up andcirculation tool insertable within a casing string in either a top driveor conventional rotary rig configuration. The torque sub 70, theoperation and benefits of which are described above, includes threeprimary components, a top sub 71, a lock sub 72 and a thread adapter 73.The inlet of top sub 71 is threadedly connected to the top drive 3 (orrotary sub if a conventional rotary rig is used). The outlet of the topsub 71 is threadedly connected to the inlet of lock sub 72. The outletof lock sub 72 may then be connected directly to the fill-up andcirculation tool selected, or it may be connected to the adjustableextension 80. The outlet of top sub 71 also includes O-ring 71 a whichprovides a fluid tight seal against the inlet of lock sub 72. Disposedabout the lower outer surface of the top sub 71 and the upper outersurface of the lock sub 72 is thread adapter 73. Thread adapter 73includes external threads 73 a, which allows the assembly to bethreadedly connected to the internal threads of a casing coupling. Thus,it will be obvious to one skilled in the art that the outside diameterof the thread adapter 73 varies with the inside diameter of theparticular casing and therefore casing coupling used. Extending from theinside wall of the thread adapter is a shoulder 73 b, which is inengaging contact with the outside wall on the outlet portion of the locksub 72. Disposed within shoulder 73 b is an O-ring 73 c, which providesa fluid tight seal between thread adapter 73 and lock sub 72. Extendinglaterally through the wall of thread adapter 73, near its upper end, arepins 74. In the preferred embodiment, four (4) pins 74 are locatedapproximately 90 degrees apart. Pins 74 extend past the inside surfaceof the wall of thread adapter 73 and extend through a slot 71 b in thelower end of top sub 71 such that the end of the pins 74 engage againstthe wall of the top sub. This fixes thread adapter 73 to top sub 71. Itwill now be obvious that as the assembly is rotated by top drive 3 (orrotary sub) to thread adapter 73 into the casing coupling, the assemblyrotates as a unitary structure. After thread adapter 73 and the casingcoupling have been made-up, elevator 14 and spider 10 (FIGS. 1 and 2)may be released allowing the entire casing string to be rotated and/orreciprocated within the wellbore. Since fill-up and circulation tool 46is still attached, fluid circulation may be performed as well.

FIG. 3 also shows the adjustable extension 80, the benefits and generaloperation of which is described above. The adjustable extension 80allows a fill-up and circulation tool of any design to be extended andretracted automatically via the top drive 3 (or a rotary sub) ormanually by simply rotating the adjustable extension 80 in the desireddirection. The adjustable extension 80 may be used in place of or inaddition to the top sub assembly or pup piece typically used to spacethe particular fill-up and circulation tool out on the rig. Theadjustable extension 80 includes a lower adapter 84, an upper adapter83, a screw mandrel 82, and an extension housing 81. The inlet of theupper adapter 83 includes threads to connect to a torque sub 70, acement head assembly (see FIG. 5), or may be connected to the top driveor rotary rig. The outlet of the upper adapter 83 is threadedlyconnected to the upper end of extension housing 81. An O-ring 83 a isdisposed within the lower outer wall of the outlet of the upper adapter80 to provide a fluid tight seal between the extension housing 81 andthe upper adapter 83. The lower end of the extension housing 81 includesa shoulder 81 a, after which threads 81 b on the inside wall extend tothe end of the extension housing 81. Threadedly connected to the lowerend of the extension housing 81 is screw mandrel 82. The screw mandrel82 includes threads 82 a substantially along the length of the screwmandrel 82 so that when the extension assembly is rotated, the screwmandrel moves axially within the extension housing 81 allowing the toolto be extended or retracted as the need arises. The upper end of thescrew mandrel 82 includes a flange 82 b, the lower portion of whichengages against the shoulder 81 a of the extension housing 82 to createa stop when the extension assembly 80 is fully extended. The upperportion of the flange 82 b engages against the outlet of the upperadapter 83 to create a stop when the extension assembly 80 is fullyretracted. Disposed within the outer wall of the shoulder 81 a areO-rings 82 c, which provide a fluid tight seal between the screw mandrel82 and the extension housing 81. Threadedly connected to the outlet ofthe screw mandrel 82 is the inlet of the lower adapter 84. Disposedwithin the inside wall of the inlet of the lower adapter is an O-ring 84b, which provides a fluid tight seal between the screw mandrel 82 andlower adapter 84. The outlet of lower adapter 84 is threadedly connectedto fill-up and circulation tool 46, the cement head assembly 47, thetorque sub 70 or other related assembly as the circumstances dictate. Atleast one slot 84 a is disposed in the outer wall of the lower adapter84. In order to retract or extend the adjustable extension 80, a bar orother suitable member is inserted into the slot and force is applied tothe bar to extend or retract the adjustable extension 80 manually. Inorder to extend or retract the extension automatically, a bar or othersuitable member of sufficient length to engage with the bails whenrotated is inserted into the slot. Thus, it will be obvious to oneskilled in the art that once the top drive 3 (or rotary sub) isactivated to rotate, the bar will move along with the lower adapter 84until the bar engages against the bail. Further rotation will cause theextension assembly 80 to be retracted or extended.

FIG. 3A shows the preferred embodiment of fill-up and circulating tool46 in the top drive configuration and in the fill-up position. Those whoare skilled in the art will know and understand that each component inthe flow path includes an inlet and an outlet. The tool consists of amandrel 19, having a central axial bore defining a flow path 19 athrough which fluid flows through the tool. A plurality of apertures 19c located near the outlet of mandrel 19 allow fluid to flow throughapertures 19 c during the circulating mode of tool 46 as more fullydescribed below. To lengthen mandrel 19 to space out the tool in anydesired length on the rig, a top sub assembly may be connected to theinlet of mandrel 19. The top sub assembly may consist of a top sub 20, afirst spacer 21, a connector coupling 22, a second spacer 23, and a topcollar 24 connected in series thereby extending the overall length ofthe tool as well as the flow path 19 a. Any number of couplings andspacers or length of spacer may be used to provide proper spacing on thetop drive or conventional rotary rig configuration. Once the spacingrequirements have been determined, the top sub assembly is configuredwith top collar 24 connected to the inlet of mandrel 19.

A spring 25 is disposed about the outer surface 19 b of mandrel 19. Theupper end 25 a of spring 25 is in engaging contact with and below lowersurface 24 a of top collar 24. A sliding sleeve 26 in engaging contactwith the lower end 25 b of the spring 25 is disposed about the outersurface 19 b of the mandrel 19. A spring stop 25 c is disposed withinthe annular space between spring 25 and outer surface 19 b of mandrel19. Spring stop 25 c is included to prevent spring 25 from being damagedfrom excessive compression. Spring 25 biases sliding sleeve 26 such thatin the fill-up mode of tool 46, sliding sleeve 26 covers the mandrelapertures 19 c, which results in fluid flow exclusively through theoutlet of mandrel 19.

The upper end of sliding sleeve 26 includes a flange portion 26 a, theupper surface of which is in engaging contact with lower end 25 b ofspring 25, and the lower surface of which is in engaging contact with aspacer ring 27. The lower surface of spacer ring 27 is in engagingcontact with a thimble 28. Thimble 28 is adapted to retain the upper end29 a of the sealing element, packer cup 29 which may be any type ofelastomeric sealing device, against and between the lower surface ofthimble 28 and the outer surface of sliding sleeve 26 near the upper end26 b. While packer cup 29 is shown as the preferred embodiment of thesealing element, any friction fit sealing device may be used, as well asother sealing devices such as inflatable packers and the like may beused in combination with the features and benefits of sliding sleeve 26and the mandrel 19 described herein.

Spacer ring 27 minimizes the potential for deflection of thimble 28 whensubjected to fluid pressure forcing packer cup 29 and thimble 28 upwardand outward. A lock sleeve 30 is disposed about the sliding sleeve 26and is connected to the lower end 26 b of sliding sleeve 26. The upperend 30 a of lock sleeve 30 is in engaging contact with the upper end 29a of packer cup 29 to further retain packer cup 29 within thimble 28 andagainst the outer surface 26 b of sliding sleeve 26. Packer cup 29depends downward with respect to the upper end 29 a of packer cup 29,flaring radially outward and away from sliding sleeve 26 such that itforms a cone which defines an annular space between the inside surfaceof packer cup 29 and sliding sleeve 26. The outside diameter of thelower end 29 b of packer cup 29 is at least equal to the inside diameterof casing 32. The lower end 29 b is further adapted to be inserted intocasing 32 and upon insertion to automatically engage with and to providea leak tight seal against the inside diameter of casing 32. Packer cup29 is formed from a flexible elastomeric material such as rubber,however other materials or combination of materials are contemplated bythe present invention. For example, in an alternative embodiment, theupper end 29 a of packer cup 29 is made of steel while the lower end 29b is made of rubber or some other elastomer.

The outlet of mandrel 19 is connected to the inlet of a lower body 31.The lower body 31 limits the travel of sliding sleeve 26 downward. Inthe fill-up mode of tool 46, spring 25 biases sliding sleeve 26 downwardsuch that the bottom surface of the sliding sleeve 26 is in engagingcontact with the top surface of lower body 31. Lower body 31 alsoprovides a conduit connection between mandrel 19 and mud saver valve 34.A guide ring 33 is connected to and disposed about the outer surface ofthe lower body 31. The guide ring 33 serves as a guide to center tool 46within casing 32 as it is lowered. The outlet of lower body 31 isthreadedly connected to a mud-saver valve and nozzle assembly.

The mud saver valve and nozzle assembly includes a mud saver valve 34,and a nozzle 35. The preferred embodiment comprises a mud saver valve 34having threads on the outer surface of the valve inlet and internalthreads on the inner surface of the valve outlet. Mud saver valve 34 isconnected to tool 46 by threadedly connecting the body extension 36 onmud saver valve 34 to the inlet of the outlet of the lower body 31. Inso doing, the body extension and a portion of lower body 31 define thehousing and annular space for mud saver valve 34 internals. A body seal36 a comprising an O-ring is disposed within a channel formed in theouter surface of the upper end of the body extension 36 to seal againstthe inner surface of the lower body 31 outlet and the pressurized fluidfrom leaking at the connection. Beginning with the mud saver valve 34internals at the outlet portion, a choke 37 is connected to a chokeextension 38 for regulating the flow of fluid from tool 46. Chokeextension 38 and body extension 36 are adapted to retain a plungerspring 39 within the space defined by a portion of the inner surface ofbody extension 36 and the outer surface of choke extension 38. A plunger40 having a central axial bore is connected to the upper end of chokeextension 40. Plunger 40 includes a centrally located protruding annularring portion 41, which is in slidable engaging contact with the innersurface of a valve housing 42. A plunger seal 40 a comprising an O-ringis disposed within a channel formed in the annular ring portion 41 toprovide a leak tight seal against valve housing 42. The upper end ofplunger 40 includes a plurality of apertures 40 b to allow fluid to flowinto the bore of plunger 40 and out of choke 37. A plunger tip 40 c isadapted to provide a fluid tight seal against plunger seat 43 a. Plungerspring 39 biases plunger 40 thereby exerting an upward force on thechoke extension 38 and therefore plunger 40 so that plunger tip 40 cengages with and provides a fluid tight seal against the plunger seat 43a. Fluid pressure exerted on plunger tip 40 c will cause plunger spring39 to depress, which creates an opening allowing fluid to flow throughmud saver valve 34, through nozzle 35 and into casing 32. The valvehousing 42 is disposed between and is in engaging contact with theplunger 40 and the lower body 31. A housing seal 42 a comprising anO-ring is disposed within a channel formed in the outer surface of valvehousing 42 to provide a leak tight seal against lower body 31. A seatring 43 having a central axial bore is in engaging contact with anddisposed within the uppermost interior portion of lower body 31 and isin engaging contact with valve housing 43 and upper body 37. A lowerbody seal 31 a comprising an O-ring is disposed within a channel formedin the lower body 31 to provide a leak tight seal against the seat ring43. The outlet of a centrally located bore within seat ring 43 definesthe plunger seat 43 a. The plunger seat 43 a is adapted to sealinglyreceive plunger tip 40 c. The seat ring 43 further includes a pluralityof spring loaded check valves 44 housed within vertical cavities 43 b.An aperture 43 c extends from each of the cavities 43 b to provide fluidcommunication between the seal ring bore and cavities 43 b. When thepressure below the seat ring 43 exceeds the pressure above seat ring 43,fluid will depressure through the check valves 44 and apertures 45 untilan equilibrium pressure above and below the seat ring 43 is achieved.The check valves 44 therefore function as safety relief valves to ensurethat high pressure fluid is not trapped below the tool, which couldresult in tool 46 being expelled uncontrollably from casing 32 as it isremoved, or in an uncontrolled pressurized flow of fluid from casing 32when the tool is removed. It will be obvious to one skilled in the artthat the uncontrolled depressurization of fluid could result insignificant downtime due to loss of fluid, damage to equipment, andinjury to personnel.

Mud saver valve 34 also functions as a check valve to actuate open whenthe fluid pressure reaches a set point pressure of about 300 psig, forexample. As the fluid pressure increases above 300 psig, plunger 40 isdepressed against spring 39 which unseats plunger 40 from plunger seat43 a, which allows fluid to flow through tool 46 and into easing 32.When fluid pressure falls below about 300 psig plunger spring 39 biasesplunger 40 upward causing plunger tip 40 c to seat against seat ring 43.Thus, mud saver valve 34 retains fluid that would otherwise be drainedand wasted from tool 46. The nozzle 35 is connected to the outlet of themud saver valve 34. Nozzle 35 is generally conical to facilitateinsertion into the casing, and includes an aperture 35 a, all of whichallow fluid to escape from tool 46 in a substantially laminar flowregime. Several mud saver valve 34 and nozzle 35 configurations arecontemplated by the present invention. For example, a hose can beconnected between mud saver valve 34 and nozzle 35, or a hose may beconnected between lower body 31 and mud saver valve 34.

To begin the fluid filling process, fill-up and circulating tool 46 islowered over casing 32 to be filled. Only the portion of tool 46 belowpacker cup 29 is inserted into casing 32. Sealing device 29 remainsabove and outside of casing 32 during the fill-up process. Fill-up offluid is accomplished by simply activating the pump 8 to fill and thendeactivating the pump 8 on completion. As the fluid pressure increaseswithin tool 46, mud saver valve plunger 40 is unseated from plunger seat43 a and fluid is allowed to flow through fill-up and circulating tool46 and into casing 32 to be filled.

FIG. 4 shows the preferred embodiment of fill-up and circulating tool 46in the rotary type configuration. FIG. 4 shows a bayonet adapter 17connected to the first spacer 21 in place of the top sub 20 on the topsub assembly. If the top sub assembly is not needed, the bayonet adapter17 may be connected directly to mandrel 19. The bayonet adapter 17includes a fluid hose connection 17 b, adapted to connect to the fluidhose 4, and a cylindrical post 17 c extending from the top of thebayonet adapter 17. The outside diameter of the post 17 c is slightlysmaller than the inside diameter of the lock block so that post 17 c maybe inserted within the bore of the lock block 18. The outer surface ofthe upper end of post 17 includes channel for receiving a spring pin,which allows fill-up and circulation tool 46 to be suspended in therotary rig configuration.

FIG. 4 also shows fill-up and circulating tool 46 in the fluidcirculation mode. Fill-up and circulating tool 46, in the rotary rigconfiguration, is shown lowered into casing 32 such that sealing element29 is in sealing engaging contact with the inside diameter of casing 32.Flow of fluid from pump 8 will cause the fluid pressure to build upinside of casing 32 until the hydrostatic pressure is overcome therebyresulting in the desired circulation of fluid from inside casing 32 intothe wellbore 12. Packer cup 29 automatically engages against the insidediameter of casing 32 as it is lowered therein. Therefore, whencirculating fluid is desired (e.g. when the casing is stuck in wellbore12), further downward force is exerted on tool 46 by lowering theassembly from traveling block 1. This causes spring 25 disposed aboutthe exterior of mandrel 19 to become compressed between top collar 24and flange portion 26 a (FIG. 3) on the sliding sleeve 26. The downwardforce causes mandrel 19 to move vertically downward with respect tosliding sleeve 26 thereby exposing the lower end of mandrel 19 andapertures 19 c formed therethrough. Pressurized fluid from the fluidpump 8 may now follow the flow path 19 a through tool 46 as well asthrough the apertures 19 c into the casing 32. As casing string 32 isfilled, the fluid pressure inside of the casing increases, which furtherengages packer cup 29 against the inside surface of casing 32. Whencirculating is no longer necessary, pump 8 is simply stopped. Thisresults in plunger 40 within mud saver valve 34 re-seating againstplunger seat 43 a, which stops the flow of fluid through nozzle 35. Tool46 is then withdrawn from casing 32 by raising the assembly suspendedfrom traveling block 1 so that the next joint of casing 32 can be pickedup or to prepare tool 46 for cementing operations.

FIG. 5 illustrates fill-up and circulating tool 46 in the cementingconfiguration. While FIG. 5 shows the preferred embodiment of fill-upand circulating tool 46 as shown in FIGS. 3, 4 and 7-9, the presentinvention contemplates and includes fill-up and circulating tools ofother embodiments. Thus, the following discussion addresses whereinfill-up and circulating tool 46 is referenced for illustrative purposes.Further, this configuration may be utilized in either the top drive rigor conventional rotary rig operations. Any fill-up and circulating toolcapable of insertion into casing may be quickly and easily switched froma drilling fluid filling and circulating mode of operation to thecementing configuration as shown in FIG. 5 by combining the selectedfill-up and circulating tool with cementing head assembly 47 and wiperplug assembly 57 of the present invention. The fill-up and circulatingtool, in the cementing configuration, is connected to and thereforeextends the flow path from a cementing head assembly 47 to a wiper plugassembly 57. Using fill-up and circulating tool 46 as more fullydescribed above, the cementing configuration comprises a cementing headassembly 47 connected to first spacer 21 of the top sub assembly, and acement wiper plug assembly 57 in place of mud saver valve 34 and nozzle35. Since the present invention contemplates and includes fill-up andcirculating tools of various other embodiments, other means ofattachment to a top drive or conventional rotary type units arecontemplated as required by the particular fill-up and circulating toolused in the cementing configuration. Additionally, cementing headassembly 47 may be directly connected to fill-up and circulating tool46.

The preferred embodiment of cement head assembly 47 includes a ball dropcoupling 48, a ball carrier assembly 49, and a ball port 50 connectingball drop coupling 48 to ball carrier assembly 49 providing a passagewaytherebetween. Ball carrier assembly 49 includes a ball carrier mandrel50, which houses a ball carrier 51 in slidable engagement with theinterior surface of the ball carrier mandrel 50. The lower surface ofthe ball carrier 51 includes a slot (not shown) within which ball stops51 b and 51 c are disposed. Ball carrier 51 a further includes a largeball seat and a small ball seat within which a large ball 52 a and asmall ball 52 b are respectively seated. Slidably disposed between largeball seat and small ball seat within slot the ball carrier 51 is ejector51 d. Attached to an upper surface of ball carrier 51 a is plunger 53which extends through an aperture in the upper end of ball carriermandrel 51. Disposed between a lower interior surface of ball carriermandrel 51 and a lower surface of ball carrier 51 a is ball spring 54.Threadedly connected to the upper end of ball carrier mandrel 51 is apressure housing 55. Pressure housing 55 houses an upper end of plunger53 and a plunger spring 56. Plunger spring 56 is disposed between a topsurface of plunger head 53 a and an inside surface on the top ofpressure housing 55. Plunger spring 56 biases plunger 53 against thebiasing force applied by ball spring 54 so that neutral position,designated by line 100, ball carrier 51 is in a position that preventsthe release of either of the balls 52 a and 52 b through ball port 50and into ball drop coupling 48. Pressure housing 55 also includespressure ports 55 a and 55 b through which a pressurization fluid(either gas, e.g. air, or hydraulic fluid) is delivered into pressurehousing 55. In the preferred embodiment the fluid pressure is suppliedby air. Thus, cement head assembly 47 may be actuated remotely torelease the appropriate ball using fluid pressure. To release large ball52 a, air pressure in the range of 90-120 psi is delivered to pressureport 55 a. The fluid pressure forces plunger 53 and ball carrier 51 downto a position such that the movement of ejector 51 d within the ballcarrier slot stops on contact with stop 51 b, the contact of whichresults in large ball 52 a being ejected through ball port 50 anddescends into ball drop coupling 48. Pressure housing 55 may bedepressurized, which allows the spring biasing forces to overcome thefluid pressure, returning ball carrier 51 to neutral position 100. Toeject small ball 52 b, air pressure is delivered to pressure port 55 b.The fluid pressure forces plunger 53 and ball carrier 51 a upward to aposition such that the movement of ejector 51 d within the ball carrierslot stops on contact with stop 51 c the contact of which results insmall ball 52 b being ejected through ball port 50 and descends intoball drop coupling 48. Again, pressure housing 55 may be depressurized,which allows the spring biasing forces to overcome the fluid pressurereturning ball carrier 51 to neutral position 100.

If fill-up and circulating tool 46 (of FIG. 3A or 4) is installed withcementing head assembly 47 and wiper plug assembly 57, it is preferableto keep cement from flowing through mandrel apertures 19 c. If cement isallowed to flow through mandrel apertures 19 c, plugging of theapertures as well as erosion may occur. To prevent this, sliding sleeve26 must be fixed in place on fill-up and circulating tool 46 of thepresent invention so that mandrel apertures 19 c remain covered duringthe cementing operation. To accomplish this, a set screw 25 d isdisposed within each of a plurality of threaded set screw apertures 25 bin the outer surface 19 b of mandrel 19 near mandrel outlet. Preferablyapertures 25 b are located a minimal distance above spring stop 25 c tofix sliding sleeve 26 in a position to cover mandrel apertures 19 cduring the cementing operations. Thus cement will not flow from mandrel19 through mandrel apertures 19 c. It is therefore desirable for thefull flow of cement to follow flow path 19 a so as to ensure properoperation of the ball dropping function, and to prevent plugging orerosion of mandrel apertures 19 c. One who is skilled in the art willreadily perceive other methods for preventing sliding sleeve 26 frommoving upward to expose mandrel apertures 19 c. For example, a tubularmember may be disposed about spring 25 between top collar 24 and slidingsleeve 26 to fix sliding sleeve 26 in place.

After the casing string has been run, it must be cemented withinwellbore 12. After the last casing joint has been filled with drillingfluid, a volume of water or flushing fluid is pumped through theassembly and into the casing. The assembly is then removed from thecasing string to be configured for the cementing mode. The fill-up andcirculating tool is then uncoupled from the top drive or rotary driveunit. The cementing head assembly 47 is coupled to the inlet of thetool. In the alternative, the cementing head assembly 47 may bepre-installed with the fill-up and circulating tool for operation inboth the drilling fluid and cementing mode. The next step is to connectwiper plug assembly 57 to lower body 31 on fill-up and circulating tool46. First, mud saver valve 34, and nozzle 35 are removed from fill-upand circulating tool 46. The wiper plug assembly 57 is then installed.The wiper plug assembly 57 comprises a top wiper plug 58 detachablyconnected to a bottom wiper plug 59. The fill-up and circulating tool isnow in the cementing configuration and is then reconnected to the topdrive or rotary unit. The next step is to release bottom plug 59 fromwiper plug assembly 47. To release bottom plug 59, the first of twotripping balls 52 a must be released from tripping ball chamber 50. Torelease tripping ball 52 a, pin 50 c is retracted, which allows ball 52a to descend from tripping ball chamber 49 and through tool 46. Thefirst tripping ball 52 a severs the connection between two wiper plugs58 and 59, which causes bottom wiper plug 59 to drop into casing string32. A calculated volume of cement is then pumped through the tool andassembly, which drives bottom wiper plug 59 down casing string 32. Asbottom wiper plug 59 descends the casing string, it wipes mud off theinside diameter of the casing. The cement drives bottom wiper plug 59 toengage with the float collar (not shown) at the bottom of casing 32.After the calculated volume of cement has been pumped, a second trippingball 52 b is released from ball dropping pump-in tee 49. The secondtripping ball severs top plug 58 from wiper plug assembly 57 anddescends into the casing string. Top plug 58 is driven down casing 32 bypumping drilling fluid or other suitable fluid through inlet port 48 bbehind top plug 58, which also wipes the cement off the inside of casing32. When sufficient pressure is generated between the two wiper plugs 58and 59, a diaphragm in bottom wiper plug 59 is ruptured, which allowsthe cement between wiper plugs 58 and 59 to flow from inside casing 32through bottom wiper plug 59 and into the annulus between casing 32 andwellbore 12. After top plug 58 has come to rest by engaging againstbottom plug 59, the discharge pressure on pump 9 begins to increase,which indicates that casing 32 has been successfully sealed off from theannulus between casing 32 and wellbore 12.

The fill-up and circulation tool of the present invention may readily beused in a tandem configuration. The tandem configuration is used when itis desired to run two different diameter casing strings, and has theadvantage of eliminating the downtime required to rig up prior artcirculation tools. The tandem configuration embodiment comprises thefill-up and circulation tool as described above, however, it includes asecond sliding sleeve and packer cup arrangement connected above thefirst sliding sleeve and packer cup wherein the diameter of the secondpacker cup 29 is larger than first packer cup 29. This allows for boththe larger and smaller diameter casing to be filled and circulatedwithout re-tooling. This arrangement can also be used with other sealingelements such as inflatable packers, and devices that seal against thecasing via and interference or friction fit with the casing.

FIG. 6 is illustrative of a push plate assembly 60. During casingoperations, it may be necessary to apply a downward force to push casing32 into the wellbore. This feature allows the weight of the rig assemblyto be applied to the top of the casing through push plate assembly 60.While FIG. 6 shows the preferred embodiment of fill-up and circulatingtool 46 as shown in FIG. 3, the present invention contemplates andincludes fill-up and circulating tools of other embodiments, includingbut not limited to those shown in the following figures. Thus, thediscussion which follows whereby fill-up and circulating tool 46referenced is for illustrative purposes. Further, this configuration maybe utilized in either the top drive rig or conventional rotary rigassemblies. The push plate assembly 60 is located between top collar 24and top sub 20 on fill-up and circulating tool 46, and is installed inplace of the standard connector coupling 22. The push plate assembly 60includes a coupling 61 with a plurality of J-shaped slots 62 withinouter wall 63 of coupling 61. A rotatable plate 64 is radially disposedabout coupling 61 and is adapted to be fixed about coupling 61 withplurality of pins 65.

To add load to the casing string, plate 64 must first be rotated untilpin 65 is engaged within the horizontal portion of J-shaped slot 62.This locks plate 64 within assembly 60 so that load may then betransferred to the casing string. Spider 10 is then engaged againstcasing 32 to hold the string in place. Elevator 14 is then released fromcasing 32 above the rig floor. The top drive unit 3 is then lowered bytraveling block 1 until plate 64 is in contact with the top of thecasing string. Elevator 14 is then attached to casing 32, and spider 10is released. The casing 32 is now being held only by elevator 14.Further lowering of top drive unit 3, adds load (the weight of the rig)to casing string, forcing the string into wellbore 12. To disengage andrelease the load from the rig, spider 10 is set against casing 32 tohold the casing string. Traveling block 1 is then raised about 6 inchesto pick up on top drive unit 3 enough to disengage plate 64 from the topof casing 32. Plate 64 is then rotated so that pins 65 are aligned withthe vertical portion of the 3-shaped slot 62. Traveling block 1 is thenlowered about 6 inches to push down on top drive unit 3 enough to allowelevator 14 to be released from casing string 32. The assembly can nowbe positioned to receive the next joint of casing 32 to be added to thestring.

FIG. 7 is a partial cross-sectional view of another embodiment offill-up and circulating tool 46 of the present invention. Tool 46includes a mandrel 19 having a bore 19 a formed therethrough in fluidcommunication between a top and bottom end, the top end being adaptedfor connecting to a top sub assembly for connecting to a rotary or topdrive as commonly known in the art and as shown in previous embodiments.Cementing apparatus 47, 49 and 50 may also be connected with tool 46 ofthe present invention as shown in FIG. 5. Tool 46 further includes athimble 28 and a sealing element 29 connected about mandrel 19 forsealing annulus between casing 32 and tool 46 when tool 46 is in thecirculating or cementing mode. Tool 46 further includes a pressurerelief housing 110 connected to mandrel 19 having a fluid pathway formedtherethrough and in fluid connection and continuing fluid pathway 19 aof tool 46. Pressure relief housing 110 forms at least one lateralaperture or port 112 which provides a fluid pathway in communicationwith the mandrel pathway 19 a for preventing flow from pathway 19 a intocasing 32 while allowing fluid flow from said casing 32 through aperture112 into pathway 19 a when pressure in casing 32 is greater then thepressure within tool 46 (pathway 19 a). In a preferred embodiment a mudsaver valve 34 and nozzle 35 are connected below pressure relief housing110.

FIG. 8 is a cross-sectional view of pressure relief housing 110. Asshown, relief housing 110 is adapted for threadedly connecting to toolassembly 46, however, relief housing 110 may be welded or be a unitarysection of mandrel 19. Formed laterally through housing 110 is anaperture 112 for allowing fluid to flow into flow pathway 19 a. Ablocking mechanism 114 is in working connection with housing 110 toprevent fluid from flowing from pathway 19 a through lateral aperture112 into the casing.

Blocking mechanism 114 as shown in FIG. 8 is a back seat check valveassembly having a plug and seat 116 forming a pathway therethrough, aball 118, and a spring 120. Housing section 110 forms a lip 122 adjacentthe inner opening of aperture 112. Disposed inside of aperture 112 andagainst lip 122 is spring 120 for biasing ball 118 away from pathway 19a and against plug and seat 116. As shown in this embodiment, plug andseat 116 is threadedly connected within aperture 112 for easy removal inorder to replace ball 118 and spring 120 when needed. Although plug andseat 116 is shown threadedly connected to housing section 110 othermodes of connecting to may be utilized such as set screws. It is alsocontemplated that ball 118, spring 120, and plug and seat 116 beconstructed as a single assembly.

With reference to FIGS. 1-8, when the well is in a static condition andpressure inside of casing 32 is substantially equal to or less then thepressure within tool within pathway 19 a, ball 118 is seated againstplug and seat 118 preventing fluid flow from inside the casing throughport 112 back into housing 110. When pressure inside casing 32 isgreater then the pressure in pathway 19 a, ball 118 is unseated fromplug and seat 116, allowing fluid to enter pathway 19 a through port 112thereby relieving pressure within casing 32. For example, when tool 46is in the circulating mode, sealing element 29 is engagingly disposedwithin casing 32. Fluid is pumped through tool 46 and ball 118 is seatedagainst plug and seat 116 preventing fluid flow through port 112. Whenpump 8 or 9 is shut down fluid is allowed to flow from casing 32 throughport 112 into pathway 19 a and past sealing element 29. In this manner,pressure is equalized across sealing element 29 allowing tool 46 a to beremoved from casing 32.

FIG. 9 is a partial, cross-sectional view of another embodiment ofpressure relief housing 110. As blocking mechanism 114, includes anelastomer member 124 for preventing fluid from pathway 19 a through port112 into the casing when pressure is greater in pathway 19 a then in thecasing. As shown, elastomer member 124 is an inverted packer cupdisposed within pathway 19 a and across port 112. Member 124 is held inplace by a locking ring 126 connected to the interior of housing 110.Many versions of this embodiment are anticipated such as, inversion of apacker cup such as the one shown, an elastomeric flapper attached acrossport 12, use of other deformable material which is biased across port112 when pressure in pathway 19 a is greater then the pressure in casing32.

In addition it is anticipated that housing 112 as shown in FIGS. 7-9 mayinclude a port 112 but not have a blocking mechanism. In thisembodiment, fluid may be pumped through tool 46 and through port 112.When pumps 8 or 9 are shut off, fluid and pressure is allowed to bypassvalve 34 and enter tool 46 through port 112 and relieve the pressurebelow sealing element 29.

Those who are skilled in the art will readily perceive how to modify thepresent invention still further. For example, many connectionsillustrated have been shown as threaded, however, it should beunderstood that any coupling means (threads, welding, O-ring, etc.).Which provides a leak tight connection may be used without varying fromthe subject matter of the invention disclosed herein. In addition, thesubject matter of the present invention would not be considered limitedto a particular material of construction. Therefore, many materials ofconstruction are contemplated by the present invention including but notlimited to metals, fiberglass, plastics as well as combinations andvariations thereof. As many possible embodiments may be made of thepresent invention without departing from the scope thereof, it is to beunderstood that all matter herein set forth or shown in the accompanyingdrawings is to be interpreted as illustrative and not in a limitingsense. Accordingly, the foregoing description should also be regarded asonly illustrative of the invention, whose full scope is measured by thefollowing claims.

1. An apparatus for cementing tubulars in a wellbore, comprising: a topdrive having a fluid path; a gripping member supported above the surfaceof the wellbore comprising radially movable gripping elements; and awiper plug assembly fluidly connected to the fluid path.
 2. Theapparatus of claim 1, comprising a member connected to the fluid path torelease a wiper plug from the wiper plug assembly when disposed into thefluid path.
 3. The apparatus of claim 1, further comprising a cementinghead assembly fluidly connected to the fluid path, the cementing headassembly remotely controlled to release a wiper plug from the wiper plugassembly.
 4. The apparatus of claim 3, further comprising a tubular bodyinterconnecting the cementing head assembly and the wiper plug assembly.5. The apparatus of claim 4, further comprising a seal member carried bythe tubular body to seal with a tubular string positioned in thewellbore.
 6. An apparatus for cementing casing in a wellbore,comprising: a tubular body having a fluid flow path therethrough; a sealmember connectable to the tubular body and the casing; a wiper plugconnectable to the tubular body; a gripping member supported above thesurface of the wellbore to grip the casing; and a top drive to move thetubular body.
 7. The apparatus of claim 6, wherein the wiper plug isremotely releasable from the tubular body.
 8. The apparatus of claim 6,further comprising a cementing head assembly fluidly connected to thewiper plug.
 9. The apparatus of claim 8, wherein the cementing headassembly is remotely controlled to release the wiper plug.
 10. Theapparatus of claim 6, wherein the tubular body is adapted to circulate afluid.
 11. The apparatus of claim 6, wherein the wiper plug isreleasable from the tubular body by a member disposed into the fluidflow path.
 12. A method for cementing a tubular in a wellbore in asubterranean formation, comprising: connecting a circulating tool to aslip and a top drive; gripping a first tubular with the slip above thesurface of the wellbore; sealingly engaging the first tubular with aseal member; fluidly connecting a wiper plug to the circulating tool;connecting the first tubular to a second tubular; and lowering thesecond tubular into the wellbore.
 13. The method of claim 12, furthercomprising rotating the circulating tool, the slip and the firsttubular.
 14. The method of claim 12, wherein sealingly engaging thefirst tubular comprises using fluid pressure to actuate the seal member.15. The method of claim 12, further comprising releasing the wiper pluginto the wellbore in response to a releasing a member into a fluid pathwith the circulating tool.
 16. The method of claim 12, furthercomprising releasing the wiper plug into the wellbore using fluidpressure.
 17. The method of claim 12, further comprising releasing thewiper plug into the wellbore after the sealing engagement of the firsttubular and without releasing the sealing engagement of the firsttubular.
 18. The method of claim 12, further comprising fluidlyconnecting a cementing head to a fluid path with the circulating tool.19. The method of claim 18, further comprising rotating the circulatingtool, the cementing head, the slip and the first tubular.
 20. The methodof claim 18, wherein sealingly engaging the first tubular comprisesusing fluid pressure to actuate the seal member.
 21. The method of claim18, further comprising releasing the wiper plug into the wellbore inresponse to a releasing a member from the cementing head into the fluidpath with the circulating tool.
 22. The method of claim 18, furthercomprising releasing the wiper plug into the wellbore using fluidpressure.
 23. The method of claim 18, further comprising releasing thewiper plug into the wellbore after the sealing engagement of the firsttubular and without releasing the sealing engagement of the firsttubular.
 24. A method of cementing a casing within a wellbore formed ina formation, comprising: connecting a gripping member disposed above thesurface of the wellbore, a cementing assembly and a top drive, whereinthe top drive and the cementing assembly are fluidly connected to afluid path; gripping the casing with the gripping member and the topdrive; sealingly engaging the casing with a seal member; moving thecasing within the wellbore via the top drive; and cementing the casingwithin the wellbore while maintaining a sealing engagement of thecasing.
 25. The method of claim 24, wherein the moving the casing in thewellbore comprises rotating at least a portion of the casing in thewellbore.
 26. The method of claim 24, wherein the cementing the casingcomprises releasing a wiper plug into the casing.
 27. The method ofclaim 26, wherein the releasing the wiper plug into the casing ispreformed after the sealingly engaging the casing.
 28. The method ofclaim 26, wherein the releasing the wiper plug into the casing comprisesdisposing a ball into the fluid path.
 29. The method of claim 28,wherein the ball is disposed into the fluid path between the grippingmember and the top drive.
 30. The method of claim 26, wherein thecementing assembly comprises a cementing head.
 31. The method of claim30, wherein the releasing the wiper plug into the casing is preformedafter the sealingly engaging the casing.
 32. The method of claim 31,wherein the releasing the wiper plug into the casing comprises disposinga ball into the fluid path from the cementing head.
 33. The method ofclaim 24, wherein the cementing is performed without releasing thegripping of the casing.
 34. A method for cementing casing in a wellbore,comprising: disposing a tubular body having a seal member from a topdrive, wherein a fluid path is formed through the top drive and tubularbody; detachably connecting a wiper plug to the tubular body; grippingthe casing with a slip above the surface of the wellbore; fluidlysealing the casing above the surface of the wellbore with the sealmember; moving the casing in the wellbore via the top drive; releasingthe wiper plug from the tubular body into the casing; and cementing thecasing within the wellbore.
 35. The method of claim 34, wherein movingthe casing comprises rotating at least a portion of the casing in thewellbore.
 36. The method of claim 35, wherein the top drive is used tomove the casing in the wellbore.
 37. The method of claim 34, wherein theseal member is positioned between the top drive and the wiper plug. 38.The method of claim 34, wherein the releasing the wiper plug into thecasing occurs after the fluidly sealing the casing and without releasingthe fluidic seal.
 39. The method of claim 37, wherein the releasing thewiper plug into the casing occurs after the fluidly sealing the casingand without releasing the fluidic seal.
 40. The method of claim 34,wherein the fluidly sealing comprises using fluid pressure to actuatethe seal member.
 41. The method of claim 34, wherein the detachablyconnecting the wiper plug is performed before the fluidly sealing thecasing.
 42. The method of claim 34, further comprising fluidlyconnecting a circulating tool to the fluid path.
 43. A method forcementing casing in a wellbore, comprising: disposing a tubular bodyhaving a seal member from a drilling rig; detachably connecting a wiperplug to the tubular body; gripping the casing above the surface of thewellbore with a slip; sealingly engaging the casing above the surface ofthe wellbore with the seal member; moving the casing in the wellbore;releasing the wiper plug from the tubular body into the casing; andcementing the casing within the wellbore.
 44. The method of claim 43,wherein the moving the casing comprises one selected from the group oflowering the casing relative to the surface of the wellbore and rotatingat least a portion of the casing.
 45. The method of claim 44, whereinthe moving the casing comprises using a top drive.
 46. The method ofclaim 44, wherein the cementing comprises maintaining the sealingengagement of the casing.
 47. The method of claim 44, wherein thereleasing the wiper plug is performed while the sealing engagement ofthe casing is maintained.
 48. The method of claim 44, wherein thedetachably connecting the wiper plug to the tubular body is before thesealingly engaging the casing.
 49. The method of claim 44, wherein theseal member sealingly engages an interior surface of the casing.
 50. Themethod of claim 44, wherein the seal member is positioned between thedrilling rig and the wiper plug.
 51. The method of claim 44, wherein thesealingly engaging the casing comprises using fluid pressure to actuatethe seal member.
 52. The method of claim 44, further comprisingproviding a circulating tool in fluid connection with the tubular body.